The present application relates generally to systems and methods for characterizing a multiphase fluid flow stream which has varying phase proportions over time, and in particular to improved systems and methods for measuring the amount of water in crude petroleum oil flowing from a high water cut hydrocarbon production well.
The following paragraphs contain some discussion which is illuminated by the innovations disclosed in this application, and any discussion of actual or proposed or possible approaches in these paragraphs does not imply that those approaches are prior art.
Background: Production and Analysis of High Water Cut Crude Petroleum Oil
Crude petroleum oil and gaseous hydrocarbons are produced by extracting them from subterranean reservoirs. Sometimes the oil and gas flows to the surface due to the natural pressure when a well is first drilled. Often, however, other methods are required to bring them, and particularly the oil, to the surface. These include a variety of techniques including driving the reservoir with injection water. A water-drive reservoir can produce a crude petroleum oil as an oil and water mixture, with water content percentages as high as 99% to just under 100% water. Note that in the petroleum industry, the water fraction in oil is known as the water cut (“WC”) and the oil fraction is referred to as the oil cut (“OC”).
The need for a very accurate determination of the water cut of crude petroleum oil is important during the taxation of crude petroleum oil and the sale of crude petroleum oil, where the owner or seller of the oil does not want to pay taxes on water, and the customer or buyer does not want to pay the price of oil for water. Thus, multiple determinations and cross-checks are often conducted on-line and off-line during petroleum production.
The offline method involves physically sampling the stream and analyzing it in a laboratory setting. In the petroleum industry, the sampling is usually done using a composite sampler which automatically opens a sample valve attached to a pipeline at some frequency to collect an aggregate sample into a sample container. The objective is to collect a sample which is representative of the production period of petroleum under consideration. After collection, the composite sample is usually picked-up by a person and taken to a laboratory. The composite sample is then “sampled” to prepare aliquots, or sub-divisions of the composite sample, for each of the various measurements, or analysis methods, to be used. However, in the case of high water cut wells, composite samplers are not routinely used because the sample is so high in water content that it is difficult, for example, to get a representative aliquot from the composite sample. Thus, the aliquot preparation itself introduces significant uncertainty into water cut determinations from high water cut wells.
Three off-line analytical methods are commonly used for determining the water content of crude petroleum oil, if a representative sample can be obtained to analyze. These are the centrifuge method, the distillation method, and the titration method. See the American Petroleum Institute (“API”) Manual of Petroleum Measurement Standards, Chapter 10. However, the API standardized methods for testing crude petroleum oil do not apply to samples with water cuts above 2%. Thus, they are not applicable to high water cut wells.
Regarding on-line methods, one method involves the use of test separator vessels. This approach generally uses a tank sized to attempt to continuously separate the well output into two or three streams, such as a gas stream, a water stream, and an oil stream, and then separately meter each stream. The Petroleum Engineering Handbook, 3rd Printing, from the Society of Petroleum Engineers, Richardson, Tex., Howard B. Bradley, editor-in-chief, 1992, describes such separators in Chapter 12, and is hereby incorporated by reference. However, the method of using test separators has several drawbacks including susceptibility to not being able to separate emulsions of oil and water, large holdup volume of water and hydrocarbon, and large physical footprint.
A major problem exists when using such separator vessel methods when the water cut is consistently above 80% and in the water continuous phase. In many cases, the only measure of oil production is obtained by producing a given well directly into a static storage tank, to allow for settling and separation of the oil and water phases as a “batch”, until the volume of oil is significant enough for liquid level measurements to be made. In the usual mode, the tank is allowed to fill, and then the liquid levels of oil and water are measured by gauging the tank with a tape measure using weights to lower the tape into the liquid mixture. Specifically, a water/oil interface-indicating material is placed on the tape measure to determine the height of the water-oil interface. The total height of the liquid level is also measured. Then, the height measurements for each phase are related back to the volume calibration table, known as the strapping table, for that particular vessel. For example, if the batch settling tank employed is shaped as a right cylinder with a flat bottom, then the heights of each settled layer, i.e. the water phase layer and the oil phase layer, are a measure of water cut. For example, if a 99% water cut oil is being produced and the right cylinder tank is filled and settled to 100 inches in height, then the oil layer will be one inch thick. This approach is very coarse, and involves personnel and dedication of one tank to the measurement of each well. This routine is also very time-consuming as most high water wells produce fluids and oil at a very reduced rate.
Accordingly, the use of rapid on-line instruments such as densitometers, capacitance probes, radio frequency probes, and microwave analyzers to measure water content of petroleum products is becoming more common to solve such problems. Additionally, on-line measurements of, for example, physical and electrical properties, via instrumentation reduces the need human involvement in the process of measuring the composition of crude petroleum oil.
Background: Water Cut by the Density and Electromagnetic Characterization Methods
On-line densitometers can be used to ascertain the amount of water in petroleum oil. One on-line density method uses a Coriolis meter. This meter can be installed in the pipeline leaving the well or wells. Coriolis meters measure the density of a fluid or fluid mixture, and usually its mass flow rate as well, using the Coriolis effect. Then, calculations can be performed to indirectly determine the water cut. For example, a Coriolis meter can measure the density of a water-oil mixture, ρmixture, and then perform a simple calculation to determine the individual fractions, or cuts, of the water phase and oil phase. By knowing or assuming the density of the dry oil, ρdry oil, and the density of the water phase, ρwater phase, then a water weight percentage, ψwater, can be calculated as follows:ψwater phase=((ρmixture−ρdry oil)/(ρwater phase−ρdry oil))×100
Note that the above equation can work equally well using the specific gravities of the mixture, dry oil, and water phase, where specific gravity is the ratio of the particular density to the density of water at four degrees Celsius.
It should be recognized that the water cut by the density method is subject to uncertainty. First, due to natural variations of, for example, the hydrocarbon composition of crude petroleum oil, the density of the dry oil can vary significantly from the assumed or inputted value required for the simple calculation. Such a value is inputted into a densitometer based on an estimate or on the history of a given hydrocarbon well or field. Crude petroleum oils can range from about 800 kilograms per cubic meter (kg/m3) to about 995 kg/m3. Further, the water encountered in hydrocarbon well production is most often saline. This salinity is subject to variability, ranging from about 0.1% by weight “salts” to about 28%. This results in a variation in the density of the water phase from about 1001 kg/m3 to about 1200 kg/m3. Again, this value would be inputted into a densitometer based on an estimate or on the history of a given well or oil field.
A further problem with high water cut oils and using density as a measure of the water cut is the “closeness” of the oil and water densities. This prevents an accurate measurement, even if the exact densities of the dry oil and pure water phase are known at the operating temperature and pressure. The error quickly exceeds 20% of the measurement at 70% water and grows larger as the water cut increases. To illustrate, consider the uncertainty associated with measuring the water cut of a 99% water cut oil using densitometry. For example, if the true exact density of the pure saline water phase is 1050 kg/m3, and the true exact density of the dry oil is 950 kg/m3, the true density of a 99% water cut oil will be 1049 kg/m3. Further assume that the density of the mixture can be measured to an accuracy of plus or minus 0.1% about the true value, which is a total uncertainty (“uncertainty band”) of 0.2%. This amount of uncertainty equates to about 2 kg/m3 units (0.002 times 1049 kg/m3 equals 2.098 kg/m3) which is larger than the true difference between the pure water phase and the true density of a 99% water cut oil, given the assumptions above. In practice, this means that the densitometer is incapable of distinguishing a 99% water cut oil from the pure water. Thus, densitometers presented with high water cut oils with close densities between the oil phase and water phase face significant challenges in accurately measuring the water cuts, or even being able to measure the water cut.
Another on-line instrument technique to determine the water cut of a crude petroleum oil is to use a microwave analyzer, instead of a densitometer, to perform the in-line monitoring of the oil and water mixture. The technique is referred to as water cut by electromagnetic measurement.
U.S. Pat. No. 4,862,060 to Scott (the '060 patent), entitled Microwave Apparatus for Measuring Fluid Mixtures and which is hereby incorporated by reference, discloses microwave apparatuses and methods which are suitable for monitoring water cuts when the water is dispersed in a continuous oil phase.
Note that the change in fluid mixture dielectric properties for a water and oil mixture can be affected by a number of parameters, including not only the percentage of water in oil, but also the individual dielectric constants of the oil phase and the water phase. For example, the dielectric constant of the dry crude petroleum oil itself can vary depending on its density and chemical composition. Note that temperature can affect the density of the oil and the water and thus the dielectric properties of each component and the mixture. However, temperature variations can easily be compensated for by using a temperature probe in-contact with the multiphase fluid being characterized to allow referencing to data sets or curves fit to the data sets for different temperatures.
Further uncertainty in conducting measurements of crude petroleum oil can be caused by the physical chemistry of the oil, the water, and the mixture itself. For example, in the case of liquid-liquid mixtures undergoing mechanical energy input, the mixture usually contains a dispersed phase and a continuous phase. For water and oil, the mixture exists as either a water-in-oil or an oil-in-water dispersion. When such a dispersion changes from water phase continuous to oil phase continuous, or vice-versa, it is said to “invert the emulsion phase”. This is a rheological phenomenon.
A further complicating phase-state phenomena of liquid-liquid mixtures is that stable or semi-stable suspensions of dispersed-phase droplets can sometimes occur. This is usually referred to as an emulsion, which can be either stable or semi-stable. Certain substances are known as emulsifiers and can increase the stability of an emulsion, meaning that it takes a longer time for the emulsion to separate into two phases under the force of gravity or using other means. In the case of petroleum oils, emulsifiers are naturally present in the crude petroleum oil. For example, very stable emulsions can occur during petroleum processing, as either mixtures of water-in-oil or oil-in-water.
For microwave analyzers, whether a dispersion or emulsion is water-continuous or oil-continuous has a significant effect on the analyzer's measurements. In the case of oil-continuous dispersions, the apparatuses and methods of the '060 patent can perform accurate water cut determinations. In the case of water-continuous dispersions or emulsions, the conductivity path established by the water continuous phase causes a significant change in the measured permittivity relative to the same proportion of phases existing as an oil continuous dispersion or emulsion. Additionally, further variations in the conductivity of the aqueous or water continuous phase caused, for example, by even relatively small changes in salinity, can significantly affect the measured permittivity results. Note that when the non-aqueous or oil phase is continuous, no conductivity path is established (because the droplets are not “connected” to form a continuous conducting circuit) and hence there is usually no significant effect on the measurements of a microwave analyzer due to the conductivity of the aqueous phase. Note also that this is only true when the wavelength of the electromagnetic energy is large compared to the emulsion size. When the emulsion size is larger than one eighth of a wavelength, the voltage difference across the emulsion can be significant and therefore a correction must be made with respect to the salinity (conductivity at the frequency of measurement) of the water.
To address the problems of phase inversion uncertainties in aqueous and non-aqueous multiphase mixtures, U.S. Pat. No. 4,996,490 to Scott (the '490 patent), entitled Microwave Apparatus and Method for Measuring Fluid Mixtures and which is hereby incorporated by reference, discloses microwave apparatuses and methods for accommodating phase inversion events. For the example of oil and water mixtures, the '490 patent discloses that whether a particular mixture exists as an oil-in-water or a water-in-oil dispersion can be determined using differences in the reflected and lost microwave power curves in the two different states of the same mixture. The '490 patent discloses microwave apparatuses and methods, including the ability to measure microwave radiation power loss and reflection to detect the state of the dispersion. In further embodiments of that invention, methods are disclosed to compare the measured reflections and losses to reference reflections and losses to determine the state of the mixture as either water-in-oil or oil-in-water, which then allows the proper selection and comparison of reference values relating the measured microwave oscillator frequency to the percentage water. An embodiment of the '490 patent is reproduced from that patent in FIG. 1B, which explained and described in detail later in this application.
However, water cut measurements using the apparatus of the '490 patent can still be subject to uncertainty in the estimation of the total oil output of a given well when the water cuts are very high, such as when they are over 90%, and approaching 100%. To illustrate, consider the uncertainty associated with measuring the water cut of a 99% water cut oil using electromagnetic characterization using a microwave analyzer. Assume that the electromagnetic characterization stage has a frequency measurement uncertainty of 1000 Hz, or 0.001 MHz. Further assume that a 3.72% shift in actual water cut percent units, or oil cut percent units, results in a 1 MHz change in frequency of the electromagnetic characterization. Thus, the resulting uncertainty band is 0.00372% wide in water cut percentage units. If this uncertainty band is applied to a 99% water cut oil, then the 1% oil cut value has an uncertainty of 0.372% (e.g. 0.00372 uncertainty span divided by 1, times 100 to convert to percent value, equals 0.372% uncertainty). If the measurement of the 1% water cut has an uncertainty of 0.372% and the oil well has an output of 100 barrels per day, the uncertainty in total production over five years is almost 680 barrels of oil.
Thus, solving the problem of accurately ascertaining the output of crude petroleum from a high water cut well presents challenges and requires solutions not adequately met by current approaches. More particularly, there is an increasing need for reduction of uncertainty in the measurement of crude oil as the value of petroleum continues to rise. More specifically, as the use and development of different production enhancement techniques continues to increase, the dynamics of compositional fluctuations at the wellhead adds further challenges to accurately determining crude petroleum oil production output.
The present application discloses systems and methods for determining the amount of water in a multiphase flow stream. A multiphase flow stream is subjected to a separation process to produce an oil-enriched fractional stream. Measurements of water content can then be made with reduced uncertainties. The amount of water in the original multiphase flow stream can be determined using the measured water content of the oil-enriched fractional stream and the flow rate of at least one of the streams through the separator.
In some embodiments (but not necessarily all), the disclosed innovations can be used at the wellhead of (or slightly downstream from) a producing hydrocarbon well, to estimate its oil, water, and gas output.
In some embodiments (but not necessarily all), the disclosed ideas can be used to estimate the water phase fraction and the oil phase fraction in a multiphase flow stream which is subjected to a single or to multiple hydro-cyclone separations.
In some embodiments (but not necessarily all), the disclosed ideas can be used to estimate the water phase fraction and the oil phase fraction in a saline water-continuous crude petroleum oil flow stream from which enough water has been removed to invert the flow stream to oil-continuous.
The disclosed innovations, in various embodiments, provide one or more of at least the following advantages:                Some of the disclosed innovations can provide methods and systems to improve the measurement of high water cut hydrocarbon well production output using a single measurement system with improved accuracy across a wide variety of operating conditions.        Some of the disclosed inventions provide more accurate physical or electrical property measurements in an oil and water mixture flow stream.        Some of the disclosed inventions reduce the number of measurements required to determine the amount of water in an oil and water mixture flow stream.        Some of the disclosed inventions provide near-real-time reduction of errors and supply more accurate results to aid in near-real-time decision-making, without requiring multiphase fluid flow stream sampling or off-line labwork conducted on such samples and thus eliminating the cost, lost opportunities, and hazards associated with such sampling.        